1. Field of the Invention
The present invention relates generally to measurement systems for determining various compositional properties of hydrocarbon streams. In another aspect, the invention concerns the use of noninvasive measurement systems in liquefied natural gas (LNG) plants to more effectively measure compositional and/or flow properties of cooled natural gas streams. In still another aspect, the invention concerns the use of noninvasive measurement systems to more effectively control separation equipment employed in a LNG plant.
2. Description of the Prior Art
It is common practice to cryogenically liquefy natural gas for transport and storage. The primary reason for the liquefaction of natural gas is that liquefaction results in a volume reduction of about 1/600, thereby making it possible to store and transport the liquefied gas in containers of more economical and practical design. For example, when gas is transported by pipeline from the source of supply to a distant market, it is desirable to operate the pipeline under a substantially constant and high load factor. Often the deliverability or capacity of the pipeline will exceed demand while at other times the demand may exceed the deliverability of the pipeline. In order to shave off the peaks where demand exceeds supply, it is desirable to store the excess gas in such a manner that it can be delivered when the supply exceeds demand, thereby enabling future peaks in demand to be met with material from storage. One practical means for doing this is to convert the gas to a liquefied state for storage and to then vaporize the liquid as demand requires.
Liquefaction of natural gas is of even greater importance in making possible the transport of gas from a supply source to market when the source and market are separated by great distances and a pipeline is not available or is not practical. This is particularly true where transport must be made by ocean-going vessels. Ship transportation in the gaseous state is generally not practical because appreciable pressurization is required to significantly reduce the specific volume of the gas which in turn requires the use of more expensive storage containers.
In order to store and transport natural gas in the liquid state, the natural gas is preferably cooled to −240° F. to −260° F. where it possesses a near-atmospheric vapor pressure. Numerous systems exist in the prior art for the liquefaction of natural gas by sequentially passing the gas at an elevated pressure through a plurality of cooling stages whereupon the gas is cooled to successively lower temperatures until the liquefaction temperature is reached. Cooling is generally accomplished by heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, and methane or a combination of one or more of the preceding. In the art, the refrigerants are frequently arranged in a cascaded manner and each refrigerant is employed in a closed refrigeration cycle. Further cooling of the liquid is possible by expanding the liquefied natural gas to atmospheric pressure in one or more expansion stages. In each stage, the liquefied gas is flashed to a lower pressure thereby producing a two-phase gas-liquid mixture at a significantly lower temperature. The liquid is recovered and may again be flashed. In this manner, the liquefied gas is further cooled to a storage or transport temperature suitable for liquefied gas storage at near-atmospheric pressure. In this expansion to near-atmospheric pressure, some additional volumes of liquefied gas are flashed. The flashed vapors from the expansion stages are generally collected and recycled for liquefaction or utilized as fuel gas for power generation.
A significant problem in the liquefaction of natural gas is that of accurately measuring compositional properties of the various cooled natural gas streams within or exiting the liquefied natural gas (LNG) plant. In the past, measurement of the compositional properties of cooled natural gas in a LNG plant was typically accomplished by extracting a sample of the natural gas and then using gas chromatography to determine its constituent parts. This sampling and analysis process was difficult and hazardous when the sampled streams included mixtures of methane, ethane, and propane at temperatures of less than −100° C. and pressures of 50 to 150 bars absolute, which are typical conditions in a LNG plant. It was also difficult to obtain consistent, repeatable analysis under the operating conditions of an LNG plant due to the error introduced during sampling and subsequent conversion to vapor for analysis.
Another common problem encountered in the production of LNG is that of measuring the rate of LNG production from the plant. Accurate flow measurement of produced LNG is very important for determining the overall performance of the plant. One conventional system for measuring the rate of LNG production employs a float in the LNG storage tank. Changes in elevation of the float in the LNG storage tank can be used to estimate the flow rate of LNG into the tank. However, this method of determining the flow rate of LNG from a plant is subject to many sources of error.
Another problem encountered in the production, transportation, and sale of LNG is that of determining the energy content (i.e., BTU content) of LNG for custody transfer purposes. Conventional sampling and analysis procedures for determining energy content have many associated errors. As such, the measured energy content of liquefied natural gas can vary by as much as 5% due to sampling and analysis error. This can be a particularly significant problem when bonus payments are contingent upon energy content-related performance guarantees.
A further problem in the liquefaction of natural gas is the removal of residual amounts of benzene, cyclohexane, and other aromatic compounds (i.e., heavies) from the natural gas stream immediately prior to the liquefaction of the natural gas stream. These heavy hydrocarbon components tend to precipitate and solidify thereby causing fouling and potential plugging of pipes and key process equipment. As an example, such fouling can significantly reduce the heat transfer efficiency and throughput of heat exchangers, particularly plate-fin heat exchangers. Conventional methods for removing heavies from natural gas in a LNG plant employ a heavies removal column that operates near the critical point of the natural gas stream. The temperature in the heavies removal column is typically controlled by measuring the temperature in the column and then adjusting the flow rate of a stripping gas to the column based on the measured temperature. However, simply measuring the temperature in the heavies removal column is only an indirect indicator of whether a sufficient amount of heavy hydrocarbon components are being removed from the natural gas. Thus, current control systems for removing heavies from natural gas in a LNG plant are relatively insensitive to the actual amount of heavies being removed.